FIG. 1 shows one example of a conventional drilling system for drilling an earth formation. The drilling system includes a drilling rig 10 used to turn a drilling tool assembly 12 which extends downward into a wellbore 14. The drilling tool assembly 12 includes a drilling string 16, and a bottomhole assembly (BHA) 18, attached to the distal end of the drill string 16.
The drill string 16 comprises several joints of drill pipe 16a connected end to end through tool joints 16b. The drill string 16 transmits drilling fluid (through its hollow core) and transmits rotational power from the drill rig 10 to the BHA 18. In some cases the drill string 16 further includes additional components such as subs, pup joints, etc.
The BHA 18 includes at least a drill bit 20. Typical BHAs may also include additional components attached between the drill string 16 and the drill bit 20. Examples of additional BHA components include drill collars, stabilizers, measurement-while-drilling (MWD) tools, logging-while-drilling (LWD) tools, and downhole motors.
In general, drilling tool assemblies 12 may include other drilling components and accessories, such as special valves, such as kelly cocks, blowout preventers, and safety valves. Additional components included in a drilling tool assembly 12 may be considered a part of the drill string 16 or a part of the BHA 18 depending on their locations in the drilling tool assembly 12.
The drill bit 20 in the BHA 18 may be any type of drill bit suitable for drilling earth formation. Two common types of earth boring bits used for drilling earth formations are fixed-cutter (or fixed-head) bits and roller cone bits. FIG. 2 shows one example of a fixed-cutter bit. FIG. 3 shows one example of a roller cone bit.
Referring to FIG. 2, fixed-cutter bits (also called drag bits) 21 typically comprise a bit body 22 having a threaded connection at one end 24 and a cutting head 26 formed at the other end. The head 26 of the fixed-cutter bit 21 typically comprises a plurality of ribs or blades 28 arranged about the rotational axis of the bit and extending radially outward from the bit body 22. Cutting elements 29 are embedded in the raised ribs 28 to cut formation as the bit is rotated on a bottom surface of a wellbore. Cutting elements 29 of fixed-cutter bits typically comprise polycrystalline diamond compacts (PDC) or specially manufactured diamond cutters. These bits are also referred to as PDC bits.
Referring to FIG. 3, roller cone bits 30 typically comprise a bit body 32 having a threaded connection at one end 34 and a plurality of legs (not shown) extending from the other end. A roller cone 36 is mounted on each of the legs and is able to rotate with respect to the bit body 32. On each cone 36 of the bit 30 are a plurality of cutting elements 38, typically arranged in rows about the surface of the cone 36 to contact and cut through formation encountered by the bit. Roller cone bits 30 are designed such that as a drill bit rotates, the cones 36 of the bit 30 roll on the bottom surface of the wellbore (called the “bottomhole”) and the cutting elements 38 scrape and crush the formation beneath them. In some cases, the cutting elements 38 on the roller cone bit 30 comprise milled steel teeth formed on the surface of the cones 36. In other cases, the cutting elements 38 comprise inserts embedded in the cones. Typically, these inserts are tungsten carbide inserts or polycrystalline diamond compacts. In some cases hardfacing is applied to the surface of the cutting elements to improve wear resistance of the cutting structure.
For a drill bit 20 to drill through formation, sufficient rotational moment and axial force must be applied to the bit 20 to cause the cutting elements of the bit 20 to cut into and/or crush formation as the bit is rotated. The axial force applied on the bit 20 is typically referred to as the “weight on bit” (WOB). The rotational moment applied to the drilling tool assembly 12 at the drill rig 10 (usually by a rotary table) to turn the drilling tool assembly 12 is referred to as the “rotary torque”. The speed at which the rotary table rotates the drilling tool assembly 12, typically measured in revolutions per minute (RPM), is referred to as the “rotary speed”. Additionally, the portion of the weight of the drilling tool assembly supported at the rig 10 by the suspending mechanism (or hook) is typically referred to as the hook load.
During drilling, the actual WOB is not constant. Some of the fluctuation in the force applied to the bit may be the result of the bit contacting with formation having harder and softer portions that break unevenly. However, in most cases, the majority of the fluctuation in the WOB can be attributed to drilling tool assembly vibrations. Drilling tool assemblies can extend more than a mile in length while being less than a foot in diameter. As a result, these assemblies are relatively flexible along their length and may vibrate when driven rotationally by the rotary table. Several modes of vibration are possible for drilling tool assemblies. In general, drilling tool assemblies may experience torsional, axial and lateral vibrations. Although partial damping of vibration may result due to viscosity of drilling fluid, friction of the drill pipe rubbing against the wall of the wellbore, energy absorbed in drilling the formation, and drilling tool assembly impacting with wellbore wall, these sources of damping are typically not enough to suppress vibrations completely.
Up to now, vibrations of a drilling tool assembly have been difficult to predict because different forces may combine to produce the various modes of vibration, and models for simulating the response of an entire drilling tool assembly including roller cone bit interacting with formation in a drilling environment have not been available. However, drilling tool assembly vibrations are generally undesirable, not only because they are difficult to predict, but also because they can significantly affect the instantaneous force applied on the bit. This can result in the bit not operating as expected. For example, vibrations can result in off-centered drilling, slower rates of penetration, excessive wear of the cutting elements, or premature failure of the cutting elements and the bit. Lateral vibration of the drilling tool assembly may be a result of radial force imbalances, mass imbalance, and bit/formation interaction, among other things. Lateral vibration results in poor drilling tool assembly performance, overgage hole drilling, out-of-round, or “lobed” wellbores and premature failure of both the cutting elements and bit bearings.
When the bit wears out or breaks during drilling, the entire drilling tool assembly must be lifted out of the wellbore section-by-section and disassembled in an operation called a “pipe trip”. In this operation, a heavy hoist is required to pull the drilling tool assembly out of the wellbore in stages so that each stand of pipe (typically pipe sections of about 90 feet) can be unscrewed and racked for the later re-assembly. Because the length of a drilling tool assembly may extend for more than a mile, pipe trips can take several hours and can pose a significant expense to the wellbore operator and drilling budget. Therefore, the ability to design drilling tool assemblies which have increased durability and longevity, for example, by minimizing the wear on the drilling tool assembly due to vibrations, is very important and greatly desired to minimize pipe trips out of the wellbore and to more accurately predict the resulting geometry of the wellbore drilled.
Simulation methods have been previously introduced which characterize either the interaction of a bit with the bottomhole surface of a wellbore or the dynamics of a bottomhole assembly (BHA). However, no prior art simulation techniques have been developed to cover the dynamic modeling of an entire drilling tool assembly. As a result, the dynamic response of a drilling tool assembly or the effect of a change in configuration on drilling tool assembly performance can not be accurately predicted.
One simulation method for characterizing interaction between a roller cone bit and an earth formation is described in U.S. patent application Ser. No. 09/524,088, entitled “Method for Simulating Drilling of Roller Cone Bits and its Application to Roller Cone Bit Design and Performance”, and assigned to the assignee of the present invention. This application discusses general methods for predicting cutting element interaction with earth formations. The application also discussed types of experimental tests that can be performed to obtain cutting element/formation interaction data. Another simulation method for characterizing cutting element/formation interaction for a roller cone bit is described in Society of Petroleum Engineers (SPE) Paper No. 29922 by D. Ma et al., entitled, “The Computer Simulation of the Interaction Between Roller Bit and Rock”.
Methods for optimizing tooth orientation on a roller cone bits are disclosed in PCT International Publication No. WO00/12859 entitled, “Force-Balanced Roller-Cone Bits, Systems, Drilling Methods, and Design Methods” and PCT International Publication No. WO00/12860 entitled, “Roller-Cone Bits, Systems, Drilling Methods, and Design Methods with Optimization of Tooth Orientation.
Similarly, SPE Paper No. 15618 by T. M. Warren et. al., entitled “Drag Bit Performance Modeling” discloses a method for simulating the performance of PDC bits. Also disclosed are methods for defining the bit geometry, and methods for modeling forces on cutting elements and cutting element wear during drilling based on experimental test data. Examples of experimental tests that can be performed to obtain cutting element/earth formation interaction data are also disclosed. Experimental methods that can be performed on bits in earth formations to characterize bit/earth formation interaction are discussed in SPE Paper No. 15617 by T. M. Warren et al., entitled “Laboratory Drilling Performance of PDC Bits”.
While prior art simulation methods, such as those described above cover either the interaction of the bit with the formation or the BHA dynamics, no prior art simulation technique has been developed to cover the dynamic modeling of the entire drilling tool assembly. As a result, accurately predicting the response of a drilling tool assembly has been virtually impossible. Additionally, the change in the dynamic response of a drilling tool assembly when a component of the drilling tool assembly is changed is not well understood.
In view of the above it is clear that a method for simulating the dynamic response of an entire drilling tool assembly, which takes into account bit interaction with the bottom surface of the wellbore, drilling tool assembly interaction with the wall of the wellbore and damping effects of the drilling fluid on the drill pipe, is both needed and desired. Additionally, a model for predicting changes in drilling tool assembly performance due to changes in drilling tool assembly configuration, and for determining optimal drilling tool assembly designs and/or optimal drilling operating parameters (WOB, RPM, etc.) for a particular depth, formation, and/or drilling tool assembly is desired.